ArPetrol Ltd. Engages Advisor for Strategic Review Process and
Provides Update on Reserves, Gas Plant, Operations and Financial
Condition
CALGARY,
Jan. 15, 2013 /CNW/ - ArPetrol Ltd.
("ArPetrol" or the "Company") (TSXV: RPT) provides
the following update regarding its strategic review process,
reserves, gas plant, operations and financial condition.
Strategic Review Process
The board of directors of the Company (the
"Board") continues to believe in the underlying value of its
assets, as demonstrated by the latest reserves review that has been
conducted, and has initiated a process to identify, examine and
consider a broad range of strategic alternatives available to the
Company. The Company has retained Raymond James Ltd.
("Raymond James") as its
financial advisor to assist the Board with its strategic review
process. Raymond James will assist
in the identification, evaluation and negotiation of potential
strategic transactions including, but not limited to, a financing,
farm-out, joint venture, merger, sale of the Company, disposition
of assets or other strategic transaction involving a third
party.
Reserves
The Company has obtained an independent audit of
the natural gas and natural gas liquid reserves attributable to
ArPetrol's interest in the Faro Virgenes concession as prepared by
Gaffney, Cline & Associates Inc. effective December 31, 2012 (the "GCA Report").
The GCA Report presented a 3% decrease in proved
plus probable natural gas reserves (gross) from 43,369 million
cubic feet ("MMcf") as of December 31,
2011 to 42,210 MMcf as of December
31, 2012. This decrease was due to volumes produced in 2012
and an adjustment to gas shrinkage. The GCA Report also presented a
28% increase to the net present value of future net revenue of
proved plus probable reserves (before deducting income tax;
discounted at 10%) from US$96 million
as of December 31, 2011 to
US$123 million as of December 31, 2012. This increase was due to a
combination of higher realized natural gas pricing (US$4 per million British thermal units ("MMBtu"))
available under the Argentine Gas Plus program and an assumed
increase in third-party gas plant revenues to reflect current
market rates.
The GCA Report was prepared using assumptions
and methodology guidelines consistent with the Canadian Oil and Gas
Evaluation Handbook and in accordance with National Instrument
51-101, Standards of Disclosure for Oil and Gas Activities.
The Company's natural gas and natural gas liquid reserves are
located in the Province of Santa
Cruz in Argentina.
Oil and Gas Reserves Based on Forecast Prices
and Costs
|
|
Natural Gas |
|
Natural Gas Liquids |
Reserves |
|
Gross(1)
(MMcf)(2) |
|
Net(1)
(MMcf) |
|
Gross(1)
(Mbbl)(2) |
|
Net(1)
(Mbbl) |
Proved Developed Producing(3)(6) |
|
1,098 |
|
928 |
|
18 |
|
16 |
Proved Developed
Non-Producing(3)(7) |
|
- |
|
- |
|
- |
|
- |
Proved Undeveloped(3)(8) |
|
25,688 |
|
21,812 |
|
433 |
|
370 |
Total Proved(3) |
|
26,786 |
|
22,740 |
|
451 |
|
386 |
Total Probable(4) |
|
15,424 |
|
13,094 |
|
260 |
|
224 |
Total Proved Plus Probable(3)(4) |
|
42,210 |
|
35,834 |
|
711 |
|
610 |
Total Possible(5) |
|
14,366 |
|
12,198 |
|
242 |
|
207 |
Total Proved Plus Probable Plus
Possible(3)(4)(5) |
|
56,576 |
|
48,032 |
|
953 |
|
817 |
Net Present Values of Future Net Revenue Based on Forecast
Prices and Costs
Reserves |
|
Before Deducting Income Tax
Discounted at 10%
(US$MM) |
|
After Deducting Income Tax
Discounted at 10%
(US$MM) |
Proved Developed Producing(3)(6) |
|
1 |
|
1 |
Proved Developed
Non-Producing(3)(7) |
|
- |
|
- |
Proved Undeveloped(3)(8) |
|
35 |
|
26 |
Total Proved(3) |
|
36 |
|
27 |
Total Probable(4) |
|
87 |
|
57 |
Total Proved Plus Probable(3)(4) |
|
123 |
|
84 |
Total Possible(5) |
|
49 |
|
32 |
Total Proved Plus Probable Plus
Possible(3)(4)(5) |
|
172 |
|
116 |
Notes: |
|
(1) |
"Gross Reserves" are ArPetrol's working interest (operating or
non-operating) share before deduction of royalties and without
including any royalty interests of ArPetrol. "Net Reserves" are
ArPetrol's working interest (operating or non-operating) share
after deduction of royalty obligations plus ArPetrol's royalty
interests in reserves. |
(2) |
"MMcf" means million cubic feet and "Mbbl" means thousand
barrels. |
(3) |
"Proved" reserves are those reserves that can be estimated with
a high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves. |
(4) |
"Probable" reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable
reserves. |
(5) |
"Possible" reserves are those additional reserves that
are less certain to be recovered than probable reserves. There is a
10% probability that the quantities actually recovered will equal
or exceed the sum of the estimated proved plus probable plus
possible reserves. |
(6) |
"Developed Producing" reserves are those reserves that
are expected to be recovered from completion intervals open at the
time of the estimate. These reserves may be currently producing or,
if shut in, they must have previously been on production, and the
date of resumption of production must be known with reasonable
certainty. |
(7) |
"Developed Non-Producing" reserves are those reserves that
either have not been on production, or have previously been on
production but are shut in and the date of resumption of production
is unknown. |
(8) |
"Undeveloped" reserves are those reserves expected to be
recovered from known accumulations where a significant expenditure
(for example, when compared to the cost of drilling a well) is
required to render them capable of production. They must fully meet
the requirements of the reserves classification (proved, probable,
possible) to which they are assigned. |
(9) |
The reserve estimates provided herein are estimates only and
there is no guarantee that the estimated reserves will be
recovered. |
(10) |
Actual natural gas and natural gas liquid reserves may be
greater than or less than the estimates provided herein. |
(11) |
The future net revenue estimates provided herein do not
represent fair market value. |
(12) |
The pricing assumptions used in the GCA Report with respect to
the net present value of future net revenue are set forth below.
Cost assumptions are based on background project work conducted in
2011 which has been updated to reflect actual costs incurred in the
2012 Faro Virgenes drilling program and have been inflated at
historical rates. The GCA Report assumes an increase in gas plant
revenues due to the upcoming expiry of the existing gas processing
contracts at the end of June 2013 and the assumption that new gas
processing contracts will be achieved at market rates. |
Gas Plant
The Company owns and operates a 100% interest in
a gas processing plant with processing capacity of 85 MMcf/d,
strategically located on the Faro Virgenes concession. The gas
plant processes third party natural gas and liquids production, in
addition to the Company's production from the Faro Virgenes
concession. As most of the gas processed by the plant originates
from third parties, the gas plant historically generated cash flow
for ArPetrol independent of production or drilling results from the
Faro Virgenes concession. Given the long useful life of the gas
plant, ArPetrol expects the gas plant to continue to generate a
stream of cash flow. Due to the upcoming expiry of the existing gas
processing contracts at the end of June
2013, ArPetrol expects to negotiate new gas processing
contracts at current market rates.
Operations update
Production volumes for the fourth quarter of
2012 were 252 barrels of oil equivalent per day ("boe/d"). This
exceeded the total year average production volume of 247 boe/d.
Average prices for natural gas and natural gas liquids for the
fourth quarter were $2.80 per MMcf
and $65.49 per barrel, respectively,
compared to total year average prices of $2.83 per MMcf for natural gas and $68.95 per barrel for natural gas liquids.
Third-party processing volumes for the fourth-quarter of 2012
averaged 74 MMcf per day. This is an increase from the total year
average third-party processing volumes of 68 MMcf per day.
Financial Condition and Outlook
ArPetrol has continued to meet with service
providers regarding outstanding costs associated with its drilling
program on the Faro Virgenes concession. ArPetrol expects a working
capital deficiency as of December 31,
2012. ArPetrol is attempting to reduce its shortfall and to
manage payment schedules with service providers for which it is
behind in payments to allow sufficient time to provide a long-term
solution for the Company. There is uncertainty regarding the
Company's ability to continue to operate as a going concern.
Additional information regarding ArPetrol's financial position can
be found in the Company's financial statements and management's
discussion and analysis for the three and nine months ended
September 30, 2012 which are
available on SEDAR at www.sedar.com.
About ArPetrol Ltd.
ArPetrol is a Calgary-based publicly traded company engaged
in oil and natural gas exploration, development and production and
third-party natural gas processing in Argentina, where it owns and operates a gas
processing facility with capacity of 85MMcf per day. The Company's
common shares are listed on the TSXV under the symbol "RPT".
Forward-Looking Information
This news release contains certain
forward‐looking information relating, but not limited, to the
Company's reserves and related future net revenue, the expected
working capital deficiency, the ability the Company to reduce its
shortfall and manage payment schedules with contractors, the
ability to negotiate new gas processing contracts upon expiry of
the existing contracts and achieve increased revenue thereunder,
the continued generation of cash flow from the gas plant, the
Company's ability to continue to operate as a going concern and the
availability of future financing or another strategic alternative.
The Company cautions readers and prospective investors in the
Company's securities not to place undue reliance on forward‐looking
information as, by its nature, it is based on current expectations
regarding future events that involve a number of assumptions,
inherent risks and uncertainties, which could cause actual results
to differ materially from those anticipated by the Company. A
number of factors could cause actual results to differ materially
from those anticipated by the Company, including but not limited to
risks associated with the oil and natural gas industry (e.g.,
operational risks in demobilization, or reactivating, drilling and
completing the well; the ability to retain staff and equipment; and
health, safety and environmental risks), weather delays and natural
disasters, union activities, change in government policies,
currency fluctuations and controls, a change in the manner and
rates at which the Company is exchanging its currency, the risk of
the expiry of the existing gas processing contracts without having
new contracts in place, the risk of interruptions to production and
processing revenue, production declines, changes in commodity
prices and revenues, increased costs, unavailability of funding or
a strategic alternative or transaction, and other risks associated
with international activity and Argentina. ArPetrol operates outside of
Canada and as such, is subject to
a number of political risks over which it has no control. The
forward‐looking information included herein is expressly qualified
in its entirety by this cautionary statement. The forward‐looking
information included herein is made as of the date hereof and the
Company assumes no obligation to update or revise any
forward‐looking information to reflect new events or circumstances,
except as required by law.
Reserves and Oil and Gas Advisories
BOE Presentation. Production
information is commonly reported in units of barrels of oil
equivalent. For purposes of computing such units, natural gas is
converted to equivalent barrels of oil using a conversion factor of
six thousand cubic feet to one barrel. This conversion ratio of 6:1
represents energy equivalency, which is primarily applicable at the
burner tip, and does not represent a value equivalency at the
wellhead. Such disclosure of boe may be misleading, particularly if
used in isolation.
Price Deck Assumptions
Year |
|
Gas
US$/MMbtu |
|
NGL
US$/bbl |
2013 |
|
2.50 |
|
70.00 |
2014 |
|
4.00 |
|
73.50 |
2015 |
|
4.20 |
|
77.18 |
2016 |
|
4.41 |
|
81.03 |
2017 |
|
4.63 |
|
85.09 |
2018 |
|
4.86 |
|
89.34 |
2019 |
|
5.11 |
|
93.81 |
2020 |
|
5.36 |
|
98.50 |
2021 |
|
5.63 |
|
101.45 |
2022 |
|
5.91 |
|
104.50 |
2023 |
|
6.21 |
|
107.63 |
2024 |
|
6.52 |
|
110.86 |
2025 |
|
6.84 |
|
114.19 |
2026 |
|
7.18 |
|
117.61 |
There are numerous uncertainties inherent in
estimating quantities of reserves and related future net revenue.
The reserves and related future net revenue set forth above are
estimates only. In general, estimates of economically recoverable
natural gas and natural gas liquid reserves and the related future
net revenue are based upon a number of variable factors and
assumptions, such as historical production from the properties,
production rates, ultimate reserve recovery, timing and amount of
capital expenditures, the scope and timing of the development
program, expected pricing and gas processing revenue, marketability
of oil and natural gas, royalty rates, the assumed effects of
regulation by governmental agencies and future operating costs, all
of which may vary materially. For these reasons, estimates of the
economically recoverable natural gas and natural gas liquid
reserves attributable to any particular group of properties,
classification of such reserves based on risk of recovery and
estimates of future net revenues associated with reserves prepared
by different engineers, or by the same engineers at different
times, may vary. The Company's actual production, revenues, taxes
and development and operating expenditures with respect to its
reserves will vary from estimates thereof and such variations could
be material. Additional information regarding ArPetrol's reserves
data and the risks and the level of uncertainty associated
therewith can be found in the Company's annual information form for
the year ended December 31, 2011
which is available on SEDAR at www.sedar.com.
The reserve data provided in this news release
presents only a portion of the disclosure required under National
Instrument 51-101, Standards of Disclosure for Oil and Gas
Activities. All of the required information will be contained
in the Company's annual information form for the year ended
December 31, 2012 which will be
available on SEDAR at www.sedar.com prior to the end of April, 2013
once ArPetrol has completed the audit of its financial and
operating results for the year.
Additional information relating to the Company
is also available on SEDAR at www.sedar.com.
Neither the TSXV nor its Regulation
Services Provider (as defined in the policies of the TSXV) accepts
responsibility for the adequacy or accuracy of this
release
SOURCE ArPetrol Ltd.